1. Field of the Invention
This invention relates to encapsulated water soluble chemicals for use in controlled time release applications, methods of encapsulating the water soluble chemicals and methods of using the encapsulated chemicals.
2. Description of the Prior Art
Water soluble particulate solid chemicals encapsulated with coatings of polymers and the like have been utilized heretofore. The encapsulating coatings on the water soluble chemicals have been utilized to control the times when the chemicals are released in aqueous fluids. For example, encapsulated particulate solid chemicals have been used in oil and gas well treating fluids such as hydraulic cement slurries, formation fracturing fluids, formation acidizing fluids and the like.
The methods of coating water soluble particulate solid chemicals have generally involved spray coating a solution of a polymer and a cross-linking agent onto the particulate solids while simultaneously fluidizing the solids with a hot gas such as air or nitrogen. The hot gas causes the polymer to cross-link and evaporates the water from the polymer solution leaving a porous film of cross-linked polymer on the particulate solids. When the coated solids are placed in an aqueous fluid, the water passes through the porous polymer film and dissolves the water soluble chemical inside. The time required for the water to pass through the polymer coating depends on its thickness, i.e., the thicker the polymer coating, the longer it takes for the water soluble chemical to leach out of the coating.
A problem has been encountered when using the prior art methods as described above to encapsulate hygroscopic or otherwise surface wet particulate solids. That is, because of the presence of the water, the sprayed on polymer solution in the presence of hot gas often fails to produce a dry encapsulating polymer coating on the solids. Problems have also been encountered when dry particulate solid chemicals which are chemically incompatible with the encapsulating polymer are encapsulated. That is, the incompatible chemicals prevent or quickly deteriorate the polymer coatings.
An example of a need for improved encapsulated chemicals in well operations involves primary cementing in deep water offshore wells. Hydraulic cement compositions are used in primary cementing operations whereby casing and other pipe strings are cemented in well bores. That is, a hydraulic cement composition is pumped into the annular space between the walls of a well bore and the exterior of a pipe string disposed therein. The cement composition is permitted to set in the annular space thereby forming an annular sheath of hardened impermeable cement therein. The objective of the cement sheath is to physically support and position the pipe string in the well bore and bond the pipe string to the walls of the well bore whereby the undesirable migration of fluids between zones or formations penetrated by the well bore is prevented.
Primary cementing operations in deep water offshore wells are particularly difficult in that they are carried out in well bores which penetrate formations between the sea floor or mud line and a depth generally under about 2,000 feet below the mud line. Such formations are often not well consolidated, readily fracture and often have highly pressured water flows therethrough. Another problem is the temperature at which the cement composition must set. Deep water off shore wells typically have sea bottom temperatures ranging from about 32xc2x0 F. to 55xc2x0 F. depending on their geographical location. The cement compositions utilized for performing cementing operations at such temperatures must set and provide enough compressive strength to proceed with drilling without involving long waiting on cement (WOC) times, preferably less than 24 hours. Accordingly, the cement compositions must include set and strength accelerating agents to allow the cement compositions to set at the low temperatures involved and to develop early compressive strengths. However, a problem in the use of cement set and strength accelerating agents is that they often cause the cement compositions to have thickening times which are too short to allow placement of the cement compositions in the formations or zones to be cemented. Thus, the cement compositions used in deep off shore wells must have adequate pumping times to allow placement, but at the same time they must set and develop sufficient compressive strengths to allow further drilling as quickly as possible.
In cementing high temperature wells which shorten the thickening times of cement compositions, a cement set retarder must be added to the cement composition to allow adequate placement time. The presence of the set retarder lengthens the WOC time of the cement composition making it necessary to add a set and strength accelerating agent to the cement composition if the WOC time is to be reduced. The presence of the set and strength accelerating agent in the cement composition increases the risk that the cement composition may thicken or set before placement.
Particularly suitable cement set and strength accelerating agents are calcium salts such as calcium chloride. If such set and strength accelerating agents were encapsulated whereby their release in cement compositions would take place after the safe placement of the cement compositions in the formations or zones to be cemented, the WOC times could be shortened appreciably. However, because calcium chloride-and other similar salts are hygroscopic, effective controlled time release encapsulation has heretofore not been possible.
Another example of a need for improved encapsulated chemicals in well operations involves dissolving drilling fluid filter cake and the like in well bores penetrating subterranean producing formations with acid or acid forming chemicals. Oil and gas wells are commonly drilled utilizing water or oil based drilling fluids. During the drilling process substantial damage to the well bore surfaces adjacent to producing formations takes place. The damage is usually in the form of a build-up of drilling fluid filter cake and gelled drilling fluid on the surface of the well bore and in the near-well bore porosity of adjacent producing formations. Unless removed, the presence of the filter cake and gelled drilling fluid hinders the flow of oil and gas into the well bore. Heretofore, the filter cake and gelled drilling fluid have been removed by the expensive and time consuming process of circulating a corrosion inhibited aqueous acid solution through the well bore and into contact with the drilling fluid and gelled drilling fluid whereby they are dissolved. An encapsulated acid or acid producing chemical which could be released adjacent to the producing formations after placement would save considerable time and money.
Thus, there are continuing needs for improved encapsulated water soluble chemicals useful in controlled time release applications, improved methods of encapsulating water soluble chemicals and methods of utilizing the encapsulated chemicals.
The present invention provides methods of encapsulating chemicals for use in controlled time release applications, encapsulated water soluble chemicals and methods of using the encapsulated chemicals which meet the above described needs and overcome the deficiencies of the prior art. The methods of this invention for encapsulating water soluble particulate solid chemicals basically comprise the following steps. A first coating is formed on the particulate solid chemical which is a dry hydrophobic film forming material or a dry sparingly soluble material. The hydrophobic material or the sparingly soluble material is present in the first coating in an amount such that it provides a dry shield on the encapsulated chemical and preferably provides a short delay in the release of the encapsulated chemical in the presence of water. A second coating is next formed on the first coating which is a porous cross-linked hydrophilic polymer. The porous hydrophilic polymer is present in the second coating in an amount such that when contacted with water it prevents the substantial dissolution of the encapsulated chemical for a selected time period.
An improved method of cementing a pipe string in a well bore of this invention is comprised of the following steps. A cement composition is prepared comprised of a hydraulic cement, water and a controlled time release encapsulated cement set and strength accelerating chemical. The set and strength accelerating chemical has a first coating of a hydrophobic film forming material or a sparingly soluble material which provides a dry shield on the encapsulated chemical and preferably provides a short delay in the release of the encapsulated chemical in the presence of water. A second coating of a porous cross-linked hydrophilic polymer is formed on the first coating which prevents the substantial dissolution of the encapsulated chemical in water for a selected period of time. After its preparation, the cement composition is placed in the annulus between the pipe string and the well bore. Thereafter, the cement composition is allowed to set into a hard impermeable mass in the annulus.
An improved method of dissolving drilling fluid filter cake and the like in well bores penetrating subterranean producing formations is comprised of the following steps. A cleaning composition comprised of water and a controlled time release encapsulated particulate solid acid or acid forming chemical is prepared. The encapsulated particulate solid acid or acid forming chemical has a first coating of a hydrophobic film forming material or a sparingly soluble material which provides a dry shield on the encapsulated particulate solid acid or acid forming chemical and provides a short delay in the release of the acid or chemical in the presence of water. A second coating of a porous cross-linked hydrophilic polymer is formed on the first coating which prevents the substantial dissolution of the encapsulated acid for a selected period of time. After its preparation, the cleaning composition is placed in the well bore adjacent to the subterranean producing formations to be cleaned. Thereafter, the cleaning composition is allowed to react with and remove said filter cake and the like.
It is, therefore, a general object of the present invention to provide improved encapsulated water soluble chemicals for use in controlled time release applications and methods of making and using such encapsulated chemicals.
Other and further objects, features and advantages of the present invention will be readily apparent to those skilled in the art upon a reading of the description of preferred embodiments which follows.
The encapsulated time release chemicals and methods of this invention are useful in a variety of applications. The term xe2x80x9ccontrolled time releasexe2x80x9d is used herein to mean that a chemical encapsulated in accordance with this invention will release at a known rate into an aqueous solution in which it is mixed in a selected time period. While any of a great variety of chemicals can be encapsulated in accordance with this invention and used in a variety of applications, the encapsulated chemicals and methods are particularly suitable for use in oil and gas well operations. Further, the encapsulated chemicals and methods of this invention are particularly suitable for encapsulating hygroscopic chemicals, but they also provide excellent encapsulation and time release for dry particulate solid chemicals.
The methods of this invention for encapsulating a deliquescent, hygroscopic or non-hygroscopic, water soluble, particulate solid chemical for use in controlled time release applications are basically comprised of the following steps. A first coating of a dry hydrophobic film forming material or a sparingly soluble material is formed on the chemical. The hydrophobic or sparingly soluble material is present in the first coating in an amount such that it provides a dry shield on the chemical and provides a short delay in the release of the chemical in the presence of water. A second coating is then formed on the dry first coating comprised of a porous cross-linked hydrophilic polymer. The porous cross-linked hydrophilic polymer is present in the second coating in an amount such that when contacted with water it delays the substantial dissolution of the encapsulated chemical for a selected period of time.
Examples of hygroscopic particulate solid chemicals which are useful in oil and gas well operations and treatments include, but are not limited to, cement set and strength accelerators such as calcium chloride, calcium acetate, calcium nitrite and ammonium chloride. Examples of non-hygroscopic water soluble particulate solid chemicals useful in well operations and treatments include, but are not limited to, oxidizing agents such as sodium chlorate, ammonium persulfate, sodium perborate, and solids such as sulfamic acid, citric acid and hydrogen sulfate salts.
When a water soluble particulate solid chemical to be encapsulated in accordance with this invention is either hygroscopic or incompatible with the release delaying polymer coating, the first coating is preferably formed of a dry hydrophobic material selected from the group consisting of styrene-butadiene rubber latex, waxes such as low melting polyolefin waxes, oils, polybutylene and atactic polyolefins. Of these, styrene-butadiene rubber latex is the most preferred.
Styrene-butadiene rubber latex is an aqueous suspension of particles of styrene-butadiene copolymers. The latex suspension usually includes water in an amount in the range of from about 40% to about 70% by weight of the latex composition, and in addition to the suspended styrene-butadiene particles, the latex often includes small quantities of an emulsifier, polymerization catalysts, chain modifying agents and the like. The weight ratio of styrene to butadiene in the latex can range from about 10%:90% to 90%:10%. A particularly suitable styrene-butadiene aqueous latex has a styrene:butadiene weight ratio of about 25%:75%, and the styrene-butadiene copolymer is suspended in a 50% by weight aqueous emulsion. A latex of this type is available, for example, from Mallard Creek Polymers, Charlotte, North Carolina under the tradename xe2x80x9cROVENE(trademark).xe2x80x9d
The hydrophobic material is preferably applied to a hygroscopic particulate solid chemical by spray coating an aqueous solution of the hydrophobic material onto the particulate solid chemical while simultaneously fluidizing the solid particles with a hot gas such as air or nitrogen. The hot gas evaporates some or all of the water from the coating solution leaving a porous coating of dry hydrophobic material on the chemical. When the hydrophobic film forming material is a rubber latex such as styrene-butadiene rubber latex, the hydrophobic film forming material becomes porous during the drying process.
The dry hydrophobic coating is generally present in the first coating placed on the particulate solid chemical in an amount in the range of from about 1% to about 25% by weight of the encapsulated chemical, more preferably an amount in the range of from about 10% to about 20%, whereby when the first coating is in contact with water it releases the chemical encapsulated thereby in a time period of less than about 2 hours.
The first coating formed on a hygroscopic material can also be formed of a sparingly soluble material. When a sparingly soluble material is utilized it can be sprayed on the particulate solid chemical in the presence of a hot fluidizing gas as described above. Alternatively, a first coating of a sparingly soluble material can be formed by reacting an outer layer of the particulate solid chemical to be encapsulated with a reactant that forms a sparingly soluble material. For example, when calcium chloride (a hygroscopic chemical) is to be encapsulated, the reactant can be sodium carbonate which reacts with an outer layer of the calcium chloride to form a first coating of sparingly soluble calcium carbonate thereon. When the particulate solid chemical is an oxidizing agent such as an alkali metal peroxide, an outer layer of the peroxide can be reacted with water soluble salts of barium or magnesium to form a first coating of sparingly soluble barium or magnesium peroxide. The reactant can be sprayed onto the particulate solid chemical while simultaneously fluidizing the chemical particles with hot gas as described above whereby a dry first coating is formed on the chemical.
Examples of dry sparingly soluble materials which can be utilized to form the first coating on a particulate solid chemical in accordance with this invention include, but are not limited to, carbonate, phosphate or sulfate salts of metals such as magnesium, barium, calcium, zirconium and the like. The sparingly soluble material in the first coating is generally present in an amount in the range of from about 1% to about 25% by weight of the encapsulated chemical, more preferably an amount in the range of from about 10% to about 20%, whereby the first coating releases the encapsulated material when in contact with water in a time period of less than about 2 hours.
While various hydrophilic polymers which can be utilized for forming the second encapsulating coating on the first coating described above, preferred such polymers comprise partially hydrolyzed acrylic polymers, preferably in an aqueous based form, which are cross-linked with either an aziridine prepolymer or a carbodiimide. More particularly, the term partially hydrolyzed acrylic polymers as used herein means any of the vinyl acrylic latex polymers containing from about 0-60% by weight monovinyl aromatic content as styrene, from about 5-25% by weight alpha, beta unsaturated carboxylic acid content and from about 15-95% by weight alkyl acrylate or methacrylate ester content. The unsaturated carboxylic acid can comprise, for example acrylic acid or methyl acrylic acid or mixtures thereof. The alkyl acrylate or methacrylate ester can comprise, for example, ethyl butyl or 2-ethylhexylacrylate, methyl, butyl or isobutyl methacrylate or mixtures thereof. The vinyl acrylic latex polymers are stabilized by the addition of appropriate nonionic or anionic/nonionic surfactant systems in accordance with well known methods for preparing and stabilizing latex polymer systems. Vinyl acrylic latex polymers of the type described above are commercially available from, for example, Rohm and Haas Company, Philadelphia, Pennsylvania or S. C. Johnson Wax, Racine, Wisconsin.
The aziridine prepolymer can comprise, for example, pentaerythritol-tris-[. beta.-(aziridinly) propionate]. The carbodiimide can comprise, for example, 1,3-dicyclohexylcarbodiimide.
The partially hydrolyzed acrylic polymers are optionally admixed with a particulate micron sized material such as silica prior to or simultaneously with the coating of the encapsulated chemical. The use of silica in the coating composition is preferred when water-soluble oxidizer chemicals which can potentially degrade a polymeric coating are encapsulated. It is also believed that the presence of silica in the coating composition also aids in introducing imperfections in the dry coating to facilitate the controlled release of the encapsulated chemical. The partially hydrolyzed acrylic polymers are admixed with the particulate silica in an amount such that the particulate silica comprises from about 0 to about 60 percent by weight of coating solids present. Preferably, the silica comprises from about 30 to about 50% by weight of coating solids present. The particulate silica can have a size range of from about I micron to about 15 microns. Preferably, the silica has a median particle size of from about 2 to about 3 microns and preferably contains less than 33 percent by weight sub-micron sized particles.
The cross-linking agent is admixed with the partially hydrolyzed acrylic polymer in an amount of from about 0.5 to about 10 percent by weight of total coating solids present. Preferably, the cross-linking agent is present in an amount of from about 2.5 to 3.5 percent by weight of total coating solids.
The second coating is preferably placed on the first coating utilizing the process described above, i.e., spray coating the particulate solid chemical while simultaneously fluidizing the solid chemical with a hot gas. The hydrophilic polymer is preferably present in the second coating in a selected amount within the range of from about 5% to about 50% by weight of the encapsulated chemical. By varying the specific amount of polymer within the above range, the time required for the second coating to allow the diffusion of water into the coating and the diffusion of a solution of the encapsulated chemical out of the coating can be varied. As will be understood by those skilled in the art, laboratory tests are conducted to determine specific release times for the polymer coating in specific amounts.
When an encapsulated particulate solid chemical is unavailable except in very small size, the high mechanical shear to which the encapsulated particles are subjected causes rupture of the coatings and premature release of the chemical. In order to overcome this problem, an aqueous solution of the chemical to be encapsulated is spray-dried onto a carrier material of appropriate size. The coating process described above is then applied to the carrier material. The ultimate particle size after the second coating should be in the range of 10 to 50 mesh, U.S. Sieve Series, or 300 to 900 microns in diameter. The total amount of the carrier material can range from about 20% to 40% by weight of the total encapsulated material. Examples of carrier materials which can be used include diatomaceous earth, ceramic beads, silica, alumina, zeolites and polystyrene beads, with silica being preferred.
An example of an encapsulated hygroscopic water soluble particulate solid chemical of this invention is a calcium chloride cement set and strength accelerator encapsulated with a first coating of styrene-butadiene rubber latex and a second coating of partially hydrolyzed acrylic polymer cross-linked with an aziridine prepolymer wherein the amounts of styrene-butadiene rubber latex in the first coating and cross-linked partially hydrolyzed acrylic polymer in the second coating are within the above mentioned quantitative ranges. Another example of an encapsulated calcium chloride set and strength accelerator of this invention is calcium chloride having a first coating of sparingly soluble calcium carbonate and a second coating of partially hydrolyzed acrylic polymer cross-linked with an aziridine prepolymer, the coatings being present within the ranges of amounts set forth above.
The improved methods of this invention for cementing pipe strings in well bores are basically comprised of the following steps. A cement composition comprising a hydraulic cement, water and a controlled time release encapsulated cement set and strength accelerating chemical is prepared. The encapsulated set and strength accelerating chemical includes a first coating of a dry hydrophobic or sparingly soluble material formed thereon and a second coating of a porous cross-linked hydrophilic polymer which releases the set and strength accelerating chemical in a known time formed on the first coating. After preparation, the cement composition is placed in the annulus between the pipe string and the well bore. Thereafter, the cement composition is allowed to set into a hard impermeable mass therein.
The set and strength accelerating chemical utilized in the above described method can be deliquescent, hygroscopic or non-hygroscopic and the materials used to form the first and second coatings are preferably selected from those described above. A presently preferred cement set and strength accelerating chemical for use in accordance with the methods of this invention is hygroscopic calcium chloride which, as described above, preferably includes a first coating formed of styrene-butadiene rubber latex and a second coating formed of partially hydrolyzed acrylic polymer cross-linked with an aziridine in the amounts set forth above.
The present invention provides an improved method of dissolving drilling fluid filter cake and the like in well bores penetrating subterranean producing formations. Oil and gas wells are commonly drilled utilizing water or oil based drilling fluids. During the drilling process, substantial damage to the well bore surfaces adjacent to producing formations takes place. The damage is in the form of drilling fluid filter cake and gelled drilling fluid build-up on the surface of the well bore and in the near-well bore porosity of the adjacent producing formations. Unless removed, the presence of the filter cake hinders the flow of oil and gas from the producing formations into the well bore. Heretofore, after drilling has been completed, the filter cake and gelled drilling fluid in the well bore and adjacent producing formations has been removed by circulating an aqueous acid solution such as aqueous hydrochloric acid through the well bore and into contact with the filter cake and gelled drilling fluid whereby they are dissolved. The aqueous acid solution must include film forming corrosion inhibitors to prevent corrosion of metal surfaces into which the acid comes into contact. The method of this invention using encapsulated acid or an acid forming chemical prevents the metal surfaces from being contacted with an aqueous acid solution before the solution becomes spent.
The improved method for dissolving drilling fluid filter cake and the like are comprised of the following steps. A cleaning composition is prepared comprised of water and a controlled time release encapsulated solid acid or an acid forming chemical. The encapsulated solid acid includes a first coating of a dry hydrophobic film forming material or a sparingly soluble material and a second coating of a porous hydrophilic polymer. The cleaning composition including the encapsulated acid or acid forming chemical is placed in the well bore adjacent to the subterranean formations to be cleaned. Thereafter, when the encapsulated acid or acid forming chemical is released, it reacts with and dissolves the filter cake and the like in the well bore and adjacent subterranean formations.
An example of a solid acid which can be utilized in accordance with the above described method is sulfamic acid.